Technical Field
Embodiments of the subject matter disclosed herein generally relate to methods and systems for acquiring blended seismic data and, more particularly, to mechanisms and techniques for generating seismic energy in a blended manner during an acquisition seismic survey.
Discussion of the Background
Seismic data acquisition and processing may be used to generate a profile (image) of geophysical structures under the ground (subsurface). While this profile does not provide an accurate location for oil and gas reservoirs, it suggests, to those trained in the field, the presence or absence of such reservoirs. Thus, providing a high-resolution image of the subsurface is important, for example, to those who need to determine where oil and gas reservoirs are located.
In traditional marine seismic acquisition, a vessel tows plural streamers having multiple seismic receivers configured to record seismic data. The vessel also tows a seismic source that imparts energy into the water. The seismic energy travels toward the subsurface and is partially reflected back to the sea surface. Seismic recorders record the reflected seismic waves.
When the source (either land source or marine source) is fired in standard data acquisition, the subsequent recording time is defined so that all useful reflected/diffracted energy is recorded before the next source is fired. This delay time imposes constraints on the acquisition rate and, hence, increases the cost of acquisition.
To reduce acquisition time, it is possible to simultaneously shoot sources. The term “simultaneously” should be loosely interpreted in this description, i.e., if first and second sources are considered, the second source may fire seconds after the first source was fired, and the shooting is still considered to be simultaneous as long as energy generated by the first source and energy generated by the second source and reflected by the subsurface are simultaneously recorded by the seismic receivers. In other words, the term “simultaneous” encompasses the case in which the second source fires during the listening time corresponding to the first source. From the seismic receivers' point of view, acquisition of simultaneous source data means that the signals from two or more sources interfere during at least part of a given listening time. By acquiring data in this way, with two or more vessels, time taken to shoot a dataset is reduced, along with acquisition costs. As an alternative to reducing acquisition time, a higher density dataset may be acquired in the same time. For such data to be useful, it is necessary to develop processing algorithms to handle source interference (cross-talk noise).
Source interference appears because subsurface reflections from an early source excitation may be comingled with those that have been sourced later, i.e., a “blended source” survey is acquired. Note that this is in contrast to conventional non-blending surveying techniques, wherein the returning subsurface reflections from one source are not allowed to overlap with the reflections of another source. Although the blended-source approach has the potential to reduce time in the field, thereby proportionally reducing survey cost, one problem is that it can be difficult to separate the individual shots thereafter, which is necessary in the processing stage. In other words, what is needed in interpreting seismic data is the depth of each reflector, and the depth of a reflector is determined by reference to its two-way seismic travel time as generated by a single source. Thus, in a multiple-source survey, the goal is to determine which of the observed subsurface reflections is associated with each source, i.e., to de-blend the data; otherwise, the two-wave travel time cannot be reliably determined.
In this regard, FIG. 1A shows sources being actuated at different spatial positions 10, 12 and 14 with time delays such that the recorded wavelets 10a-c corresponding to spatial position 10 do not interfere (in time) with wavelets 12a-c corresponding to spatial position 12. The signal recorded at the receiver can be considered a single continuous recording/trace (16). Alternatively, single trace 16 may be divided into plural traces, based on the listening time associated with each shot point 10, 12 and 14. In this way, continuous trace 16 is split into regular seismic traces for each individual shot as shown in FIG. 1B. Traces illustrated in FIG. 1B form a receiver gather 20. Each trace in receiver gather 20 relates to a different shot, i.e., has a given location in the field, which is illustrated by having different values on axis X (m), and each wavelet has a different time on a temporal axis t (s).
FIG. 2A shows a similar source configuration, but now the sources are simultaneously activated so that, for example, wavelet 10c might be superimposed (in time) over wavelet 12a, resulting in blended data. FIG. 2B shows the receiver gather 30 formed though pseudo-de-blending. Pseudo-de-blending involves forming regular seismic traces from continuous recording based on the start time of each shot's actuation, with no attempt to mitigate cross-talk noise. The data of FIG. 2B has been shot in less time than the data in FIG. 1B, but cross-talk 32 is observed, and noise on one trace is signal on another trace.
Thus, for gather 30 in FIG. 2B, it is necessary to separate the energy associated with each source (de-blend) as a preprocessing step, and then to proceed with conventional processing. To make separation easier, it is generally advantageous to use a variety of different source signals, for example, different vibroseis sweeps or pseudo-random sweeps for land acquisition. When energy from a given source is correlated with the sweep signal, this allows a designature operator to be applied on the acquired seismic data, which results in focusing the energy of that source while keeping energy from other sources dispersed. The actual timing of the shots may also be used to successfully de-blend the energy from the sources.
To acquire the seismic data illustrated in FIGS. 1A-B, the 3-dimensional (3D) seismic data acquisition system 300 illustrated in FIG. 3A may be used (note that streamers and corresponding seismic sensors are not shown in FIG. 3A for simplicity). The system includes a vessel 302 that tows a pair of source arrays 304 and 306. Source arrays 304 and 306 are alternately activated along corresponding source lines 304A and 306A with a shot point interval d so that source array 304 is activated at odd shot point locations 1001, 1003, etc., and source array 306 is activated at even shot point locations 1002, 1004, etc. Symbols S1 and S2 are used throughout the specification to illustrate the positions of the source arrays when shot. FIG. 3B shows a temporal view of the source arrays' activations in this traditional seismic acquisition system. Note that the acquired seismic data is not blended because the shot point interval d is large enough to allow energy from a previous shot to die down before the next shot.
A new acquisition system that shoots blended data, as illustrated in FIGS. 2A-B, for reducing the acquisition time, is desired and now discussed.